GOVERNMENT POLYTECHNIC BHUJ · Electrical Engineering Department

CO5 Audited Virtual Lab: IBR-Integrated Feeder Protection

Directional supervision and adaptive overcurrent setting groups for a current-limited solar-PV source

Switchgear and ProtectionDI05009011 Semester 5Academic Year 2026–27 Balanced 3-Phase RMS ModelOffline Browser Lab
CO5: Implement modern techniques to mitigate fault challenges in networks integrated with renewable energy sources.

Experiment

To analyse protection challenges created by a current-limited solar-PV inverter in a radial distribution feeder and apply directional supervision and adaptive relay setting groups.

Aim

Calculate balanced three-phase fault currents, determine the currents measured by primary and backup relays, evaluate IEC IDMT operating times, and verify selective circuit-breaker operation.

Learning outcomes

  • Compare conventional-grid and inverter fault-current behaviour.
  • Identify reverse-current sympathetic-tripping risk.
  • Check pickup security, fault sensitivity and grading margin.
  • Apply explicit setting groups and directional supervision.

Case A

Downstream feeder fault with PV disconnected.

Case B

Upstream bus fault with remote PV and fixed non-directional protection.

Case C

Repeat Case B with directional and adaptive protection.

Deliberate scope: This audited version uses a balanced three-phase RMS fault. Unbalanced faults are not represented by arbitrary multipliers; they require positive-, negative- and zero-sequence networks plus an inverter sequence-control model.

Theory

Grid fault current

The grid is represented by a positive-sequence Thevenin impedance obtained from short-circuit level and X/R ratio. For a downstream fault, the impedance of the feeder section up to the fault is included.

|Zs| = VLL² / Ssc

Igrid = Vphase / |Zs + Zline + Rf|

Inverter fault response

The PV inverter is represented as either a current-limited ride-through source or momentary cessation. The ride-through current is based on rated current and the selected current limit, not multiplied directly by solar operating power.

Ipv,rated = Ppv / (√3 VLL)

Ipv,fault = klim × Ipv,rated

IEC IDMT relay

t = TMS × k / [(I / Ipickup)^α − 1]

Curvekα
IEC Standard Inverse0.140.02
IEC Very Inverse13.51.0
IEC Extremely Inverse802.0
Adaptive setting groups: SG-A is used without PV; SG-B is explicitly entered and selected when PV is connected. No hidden setting multiplier is applied.
Directional supervision: R2 is blocked when current flows in reverse from a remote PV source toward an upstream bus fault.

Pre-Test

1. Compared with a synchronous source, a grid-connected inverter fault current is generally:

2. For selective feeder protection, the relay nearest the downstream fault should:

3. A directional element is needed to distinguish:

4. An adaptive relay setting group changes according to:

5. Relay pickup should normally be:

Single-Line Diagram and Ratings

Network ratings appear here.
GRID50 MVA SCThevenin source R1 BackupCB1 SOURCE BUS R2 PrimaryCB2 LOAD2 MWRadial feeder 5 km feeder SOLAR PVDisconnected Orange: forward grid current · Purple: reverse PV current
Grid fault current
—
balanced RMS
PV contribution
—
ride-through/cessation
R1 measured current
—
backup relay
R2 measured current
—
primary relay
R1 operating time
—
IEC IDMT
R2 operating time
—
IEC IDMT
Grading margin
—
relevant relay pair
First breaker
—
predicted operation
Select a preset or parameters, then run the simulation.

Effective settings and calculated impedances

Values appear after simulation.
Relay currents and breaker operation
IEC relay operating-time comparison

Procedure

1
Select A: No PV feeder fault. Verify that R2 operates before R1 and that the grading margin is adequate.
2
Select PV at source bus. Compare the PV contribution, R2 current and operating time with Case A.
3
Select B: Reverse-feed risk. A remote PV source feeds an upstream bus fault through R2 in reverse direction.
4
Observe whether the fixed non-directional R2 trips sympathetically before R1.
5
Select C: Directional mitigation. Verify that R2 is blocked for reverse current and R1 clears the bus fault.
6
Select PV momentary cessation. Compare its zero PV fault contribution with current-limited ride-through.
7
Change SG-A and SG-B settings. Ensure pickup security, fault sensitivity and grading margin are all acceptable.
8
Add observations, export CSV, complete the post-test and generate the conclusion.

Observation Table

CasePV statusPV response/locationFault zoneIgrid (A)Ipv (A)IR1 (A)IR2 (A)tR1 (s)tR2 (s)Margin (s)GroupMethodResult

Post-Test

1. The audited model does not use fixed multipliers for L-G and L-L faults because:

2. During momentary cessation, the PV fault-current contribution in this model is:

3. For a remote-PV upstream bus fault, directional supervision should:

4. SG-B is selected in adaptive mode when:

5. A secure pickup check requires pickup to exceed:

Methodology Audit

Removed from the first version
  • Unjustified fixed factors for L-G, L-L and L-L-G fault currents.
  • PV fault current multiplied directly by solar operating percentage.
  • Source impedance treated as purely resistive.
  • Hidden adaptive-setting multipliers.
  • Arbitrary 30-second cap on IEC relay time.
  • Feeder impedance incorrectly included in an upstream bus fault.
Implemented in this audited version
  • Balanced positive-sequence three-phase RMS fault model.
  • Grid short-circuit level with explicit X/R decomposition.
  • Current-limited ride-through or momentary cessation.
  • Explicit SG-A and SG-B relay settings.
  • IEC SI, VI and EI curves without hidden time clipping.
  • Pickup security, sensitivity and grading checks.
Use limitation: This is an educational phasor-domain laboratory. It is not an EMT inverter model, relay commissioning tool, CT-saturation model, arc-flash study, or utility-grade protection-setting package.

Result and Conclusion

No conclusion generated yet.

Suggested result statement

A current-limited inverter-based resource can change the magnitude, location and direction of fault-current contribution. Fixed non-directional overcurrent protection may operate undesirably when a remote PV source feeds an upstream fault. Explicit adaptive setting groups improve coordination for changing operating conditions, while directional supervision prevents reverse-current sympathetic tripping.

References used to frame the educational model

  • MathWorks, “Overcurrent Relay Protection in AC Microgrid” — relay coordination, phase/earth protection and standard IEC/IEEE characteristics.
  • National Renewable Energy Laboratory, “Protection” — inverter fault responses differ from synchronous generators and can provide only a small amount above rated current or cease current rapidly.
  • NREL/NLR studies on IBR controls and relay elements — current limiting, momentary cessation and operating conditions affect protection response.